“assessment of the potential, the actors and relevant

“Assessment of the Potential, the Actors

and Relevant Business Cases for Large

Scale and Long Term Storage of

Renewable Electricity by Hydrogen

Underground Storage in Europe”

Grant agreement no.: 303417

Executive Summary

Status:

Final

Dissemination level:

PU – Public

Final:

23 JUNE 2014

Final / PU – Public

Grant agreement no. 2/18 23 June 2014

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European context and the need for electricity storage

The European Union has set itself ambitious climate protection targets which call for

a transformation and decarbonisation of the energy system in Europe. The targets for

2020 are a 20% reduction of greenhouse gas (GHG) emissions, a 20% share of

renewable energy sources (RES) in the energy mix and a 20% reduction in primary

energy use. The EU’s long-term strategy until 2050 envisages an 80% to 95%

reduction of GHG emissions compared to 1990 levels.

Achieving these demanding targets will require a fundamentally different energy

system, with renewables such as onshore and offshore wind and photovoltaic (PV)

energy playing a crucial role in the electricity generation mix. Unlike the energy

sources used in conventional power plants, these renewable sources are not

dispatchable and they fluctuate over time, resulting in intermittent feed-in of electricity

into the grid.

As the European energy system decarbonises, the greater reliance on intermittent

renewable energy sources poses a number of challenges concerning their large-

scale system integration: most importantly, this includes temporary mismatches

between supply and demand as well as growing strains on the grid. This will require

a mix of different solutions to maintain grid stability. Generally considered solutions

are flexible fossil-based generation, grid expansion, demand-side management of the

structural final demand for electricity, electricity storage (including conversion to other

energy carriers such as hydrogen), flexible electrification of heat demand with hybrid

heating systems and curtailment of surplus intermittent generation capacity.

The specific characteristics of the energy systems and national energy policy

approaches vary significantly across European countries. This will be reflected by

differences regarding the challenges of integrating renewables from a capacity and

regulatory perspective. It will also affect the possibility for application of any particular

solution, and the mix of flexibility measures to be applied. In any case, ongoing

decarbonisation and increasing reliance on fluctuating renewable energy sources are

expected to create an increased demand for energy storage technologies.

In general, the need for electricity storage is driven by the extent to which the

electricity system is subject to (temporary) mismatches between supply and demand,

which may also result in more volatile electricity prices. In those cases, storage can

serve as a buffer, which absorbs surplus electricity generated from renewable energy

sources at times when supply exceeds demand, and can provide additional capacity

in deficit situations, when the volatile generation is not sufficient to cover the

electricity demand. This creates opportunities for electricity time shift and conversion

to other energy carriers.

Key parameters which determine supply-demand mismatches and the resulting need

for storage include, on the one hand, the amount of installed intermittent renewable



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generation capacity (onshore and offshore wind, PV), their specific generation

characteristics (i.e. the wind speed and solar irradiance profiles), and on the other

hand the electricity demand profile.

Additionally, the geographical distribution of generation and consumption centres,

and the availability of interconnecting grid capacity have an impact on the demand for

electricity storage. The type of storage solutions and the need for ancillary services,

like frequency control, will also differ depending on the voltage level at which

renewable electricity is fed into the grid, i.e. at the low-voltage local distribution grid,

or the high-voltage transmission grid.

The case for underground storage of hydrogen

The electrolysis of water to produce hydrogen in combination with hydrogen

underground storage, where geologically feasible and acceptable to the public, is a

readily available and technically feasible option for TWh-scale storage of fluctuating

renewable electricity over extended periods of time, in the order of weeks up to

months. As a result, there is a rapidly growing interest in the role electrolytically

produced hydrogen could play for the system integration of intermittent renewables.

The unique aspect of hydrogen as energy storage medium is its use as ‘universal

energy vector’, i.e. its versatility with regard to a range of end-use applications. It can

be used for re-electrification, in which case it can be considered as ‘classical’

electricity storage option; but it can also be used in other sectors beyond the

electricity system. Examples are the use as vehicle fuel for fuel cell electric vehicles

(FCEV); the use as feedstock and even as heating fuel in industry, such as the

chemical and petrochemical industry, and the steel industry; and for the greening of

natural gas by admixing hydrogen into the natural gas grid (within technically

acceptable limits).

Against the background of the European policy goals to significantly reduce

greenhouse gas emissions by increasing the share of renewable energies in all

energy sectors, there is an opportunity to leverage synergies between hydrogen as a

storage medium and as a potentially ‘green’ fuel (e.g. from shared infrastructures),

which enables the extensive deployment of intermittent renewables for applications

other than typical electricity applications, most notably for mobility and industry.

The HyUnder project – objectives

Following this promising perspective, the objective of the HyUnder project was to

assess the potential of hydrogen underground storage in Europe, taking geological

and geographic factors into account, and to assess the feasibility of the business

cases for conversion of renewable electricity into hydrogen in combination with large-



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scale underground storage. Although the European perspective is taken as starting

point, the more detailed analyses in the project have been focussed particularly on

the six European countries that were part of the project consortium, i.e. France (FR),

Germany (DE), the Netherlands (NL), Romania (RO), Spain (ES) and the United

Kingdom (UK).

Potential scale of the challenge – estimates for surplus electricity

It has been assumed that underground storage of hydrogen will initially be driven by

an increase in “surplus” renewable electricity, being defined to occur when the

difference between the electricity generation from renewable sources and

conventional (must-run) power plants exceeds the overall electricity demand at any

given point in time. Obviously, the moment, extent and location of the occurrence of

this surplus depend on the speed, scale and type of renewable electricity rollout.

Basic assessments of supply-demand mismatches, assuming an ideal “copper plate”

electricity transmission system, and thus neglecting any possible network

congestions, have been carried out on a national level to provide an indication of the

maximum potential for storage of surplus. Locally or regionally, however, the

occurrence of specific grid bottlenecks may increase the need for storage.

Longer term, with a very high (>60%) intermittent renewables share in the generation

mix, an increasing need will develop to manage deficit situations as well, which

requires electricity time shifts over extended periods for which hydrogen storage is a

very feasible option. It is not at all clear today how solutions for such a future look

like, but they could require significant use of hydrogen for re-electrification which

would then not be available anymore for other uses.

It is important to note, though, that the scenarios have not taken into account other

storage technologies, such as batteries, to be rolled out at large-scale, which would

reduce any surplus available for conversion to hydrogen. Furthermore, the

quantification of surplus also depends on future electricity demand patterns.

The following table provides a high-level overview of the country case study

estimates on annual surplus electricity, and – assuming 100% conversion to

hydrogen – the hydrogen supply potential for different applications as well as rough

estimates of the potential number of caverns, installed electrolyser capacity and

related investments.1 The numbers are of hypothetical nature and meant only to give

an indication about the potential market size for underground hydrogen storage and

subsequent hydrogen applications; as other storage technologies and flexibility

measures are being put in place, actual numbers are expected to be lower.

1 Numbers in the table may slightly deviate from case study results, due to differences in assumptions. Data from the French

case study are not included due to differences in the approach.



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Table 1: Overview of country case study assessments

Germany Netherlands Spain UK Romania

2025 2050 2025 2050 2025 2050 2025 2050 2025 2050

Surplus/a [TWhel] 15 75 1 43 8 24 6 21 1 1

% intermittent RES

of total electricity

demand

30% 70% 31% 80% 32% 65% 42% 62% 13% 14%

% surplus of

intermittent RES

generation

9% 19% 3% 30% 3% 6% 8% 11% 9% 10%

H2 equivalent [kt]2 297 1,485 26 844 162 471 113 416 19 28

#FCEV (million)3 3.7 18.3 0.3 10.5 2.0 5.8 1.4 5.1 0.2 0.3

% passenger car fleet 8% 42% 4% 133% 8% 24% 4% 16% 5% 7%

% natural gas use 3% 15% <1% 9% 2% 5% 1% 4% <1% <1%

% H2 demand industry 8% 41% 3% 93% 24% 88% 16% 59% 16% 19%

No. of caverns4 15 74 1 43 8 24 6 21 1 1

Electrolyser

capacity [GW]5

5 25 0.5 14 3 8 2 7 0.3 0.5

Investment in

electrolysis [B€]6

5.6 18.7 0.5 10.7 3.0 6.0 2.1 5.2 0.3 0.3

In the above table, the annual estimated surplus electricity has been converted into

the theoretical amount of hydrogen that could be made available for use in different

applications (which are mutually exclusive in this case). In principle, end use options

for this hydrogen are its use as a fuel in the potentially emerging mobility sector,

selling it to industrial hydrogen customers, admixing it to the natural gas grid, and for

re-electrification. In the case of industry this would largely be a substitution of today’s

fossil-based hydrogen production, whereas the other sectors would generate new

demand and new markets for hydrogen. With FCEVs on the verge of market

introduction, hydrogen as vehicle fuel currently receives considerable attention.

However, in the short to medium term, potential hydrogen demand for mobility will be

small compared to what could be fed into the natural gas grid or the existing

substitution potential in the industry sector.

Clearly, the results illustrate that the estimated amount of surplus, if converted

entirely to hydrogen, could fuel a significant number of FCEVs in some cases, such

as in Germany. Also, it could replace a large share of industrial hydrogen which is

currently produced mainly from natural gas. Building such an infrastructure of

2 Assumes 100% conversion to hydrogen, 66% efficiency.

3 Based on 0.54 kg H2/100 km and 15,000 km per year.

4 Assumes a mature-market cavern size of 500,000 m

3 with a hydrogen net storage capacity of 4 kt; based on simulations of

charging/discharging patterns and the hydrogen inventory of the cavern, the required total storage capacity is roughly 20% of the total amount of hydrogen produced from surplus; cavern construction costs for brown field sites of 60 €/m

3, resulting in

some 30 M€ (excl. cushion gas). 5 Based on 2,000 full load hours.

6 Assumes investment of 700 €/kWel for electrolysis in 2025 and 500 €/kWel in 2050.



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integrated hydrogen electrolysis and underground storage sites would require

significant multi-billion Euro investments, with installed electrolyser capacities of

several GWs.

Site mapping of potential underground hydrogen storage sites

A geological mapping of European regions for underground storage of hydrogen has

been performed in the project, considering both rock salt deposits and porous

formations. A quantitative analysis has focused on the potential of salt deposits for

the construction of caverns, as the preferred option for hydrogen storage, mainly for

reasons of operational flexibility and lower levels of potential contamination of the

hydrogen with in-situ materials; further research is required to assess the feasibility of

hydrogen storage in porous formations, such as aquifers and depleted gas fields.7

Salt deposits suitable for cavern construction are unevenly distributed geographically

and do not necessarily occur in those regions that have the highest potential for

cavern storage; in this respect the northern parts of Germany and the Netherlands

seem particularly promising.

The regional potential in the six countries for salt cavern construction is shown in

Figure 1. The colour code reflects the storage potential of a certain area, defined as

the presence of a salt structure or salt deposit suitable for the construction of

hydrogen caverns. The map also shows that salt deposits are unevenly distributed

throughout Europe and highlights the need for other hydrogen storage options where

salt is absent (such as in porous formations).

7 Through collaboration with supporting partners from industry as well as other regions within and outside of Europe the scope

of the HyUnder project was broadened. Whereas the supporting partners from different industry sectors contributed specifically to the analysis of the individual six country case studies, supporting partners from Argentina and Denmark addressed further regional aspects of hydrogen underground storage. The ongoing activities to test the impact of hydrogen admixture to a depleted natural gas field in Patagonia enriched the discussion and highlighted the need to perform practical tests to get reliable results.



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Figure 1: Geological mapping of salt formations and selected storage sites8

The geological conditions, i.e. the depth and thickness of the deposit, the nature and

amount of insoluble rock components in the salt, and the structural style of the

deposit are the main parameters to determine the feasibility of building a storage

cavern.

Besides, other non-geological location factors have been taken into account in order

to determine promising site locations. Most importantly, this may be the access to

nearby brine processing facilities for salt or chlorine production, or brine disposal

options (like the sea, where allowed). The availability of cheap electricity (e.g. by 8 The assessment of the salt deposits was made based on an approach to design model caverns, on the available geological

information and common cavern construction limitations. However, salt deposits in some locations were assessed directly by the case study participants, based on different parameters or with additional data available. Thus for the UK and Romania, sites have been selected for the case study assessment that show no significant potential based on the cavern model.



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eliminating grid fees) as well as access to potential future hydrogen markets are

other important considerations (see Figure 2). With respect to all considered factors,

Germany, the Netherlands and the UK seem the most suitable countries for

hydrogen storage in salt deposits.

Figure 2: Qualitative assessment of the suitability of countries for hydrogen storage

Site selections will likely face a trade-off between different location factors, like the

location’s vicinity to renewable electricity hubs – especially when they are highly

centralised such as for the landfall points of offshore wind energy – versus its vicinity

to existing hydrogen infrastructure and hydrogen demand centres. Where possible,

existing natural gas storage sites (initially) are preferred locations to start developing

hydrogen caverns. There are a number of reasons for this, like lower expected

development costs compared to green field sites because of existing leaching and

brine processing infrastructure and lower exploration costs, possible extension of

existing permits, and familiarity in the area with gas storage which might avoid, or

help in overcoming potential issues regarding public acceptance.



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Economic assessment of underground hydrogen storage and business cases

An integrated underground hydrogen storage facility for large-scale electricity storage

typically consists of the following elements (see Figure 3):

- A water electrolysis unit for production of hydrogen

- A compressor unit for pressurization of the hydrogen for storage

- A salt cavern for storage of the hydrogen

- A purification section with drying unit and pressure swing absorption (PSA)

Figure 3: Flow chart of integrated electrolysis and underground hydrogen storage facility

As illustrated in Figure 4, electrolysis dominates the total specific hydrogen plant-gate

costs (CAPEX and OPEX) of an integrated hydrogen storage facility with over 80%.9

The hydrogen production costs from electrolysis are mainly influenced by the capital

costs of the electrolyser, its utilization and the (average) electricity purchase price

during the time of operation.10 Other costs such as water costs or operating and

maintenance costs are of minor relevance.

9 The respective shares of the CAPEX only are some 60% for the electrolyser, 30% for the topside equipment (compression

and purification), and 10% for the cavern construction. 10

For a given utilization, the average annual electricity purchase price can be calculated from the electricity price duration

curve.

Simplified Process Flow Chart

Electrolyser

Compressor

Cavern

Trailerfillingstation

Purification (PSA)

Buffer storage,Dryer

Buffer storage

Transformer

Electricity

Hydrogen

optional



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Figure 4: Cost breakdown of an integrated electrolysis and hydrogen storage facility

A key factor determining the costs of electrolysis is the utilization, all the more in the

context with intermittent renewable electricity generation. A high electrolyser

utilization reduces the specific share of electrolyser capital costs in hydrogen

production cost; on the other hand, a higher utilization increases electricity costs, as

hours of expensive electricity will increasingly be included. Hence, in order to

minimize hydrogen costs, electrolyser utilization has to be balanced with the

electricity price.

The economic simulation of an electrolyser shows that the optimum utilization,

resulting in lowest hydrogen production costs is in the order of 3,000 to 6,000 hours,

with a relatively flat cost profile in this range. With less than 2,000 operating hours,

the high relative share of the electrolyser CAPEX increases the hydrogen costs to an

uncompetitive level. For a utilization of 40-50% and average wholesale electricity

prices of 40-50 €/MWhel, electricity costs alone account for more than 50% of

electrolysis costs in most cases; this illustrates that production costs are very

sensitive to electricity prices during operation. Electricity prices, however, may vary

significantly between countries.11

For a better understanding of the average utilization of electrolysers run by ‘surplus’

electricity it is useful to calculate residual load duration curves for different

penetration levels of intermittent renewables.12 Figure 5 (left side) depicts typical

residual load duration curves for a 30% and 80% share of intermittent renewables

generation of total electricity demand, estimated for 2025 and 2050 respectively.

11

In reality, electricity prices may be significantly higher, with country-specific taxes and fees added to the wholesale price. 12

Residual load is the difference between the total electricity demand and the residual demand. The latter corresponds to all

power generation options excluding wind and solar-PV. Residual load consists, therefore, only of wind and solar-PV.

Electrolysis Topside facilities Cavern Distribution

EU

R/k

g H

2

Elec

trici

ty c

ost



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Figure 5: Residual load and surplus electricity duration curves from the Dutch case study

The part of the curves under the x-axis is a measure for the amount of electricity that

is produced, but for which there is no immediate demand;13 these surplus electricity

duration curves are shown at the right hand side of the graph. Clearly, in 2025 the

amount of surplus is still limited, occurring in the order of 500-1,000 hours per year,

due to the low (<30%) share of fluctuating renewable electricity generation. By 2050,

with an intermittent renewables share of some 80%, substantial amounts of surplus

electricity occur during a total of 4,000-5,000 hours within a year; however, without

considering any other storage technologies or flexibility measures being implemented

over time.

The following figure illustrates, again exemplarily for the Dutch case study, how the

specific hydrogen production costs at plant gate depend on the actual utilization of

the electrolyser. The bandwidth shown at the left-hand side of the figure mainly

indicates differences in average electricity price assumptions and electrolyser

CAPEX.14 At a low utilization of less than 1,000 hours, hydrogen costs are

prohibitively high, in the order of at least 10 €/kgH2 and more. This means that the

electrolyser would have to be operated with additional electricity purchased from the

power exchange (grid) at lowest possible prices, in order to reach a utilization that

minimises the hydrogen production costs to a cost-competitive level; depending on

the CO2 intensity of the grid mix, however, this will effectively increase the CO2-

footprint of the hydrogen produced. Between 3,000 and 4,000 hours hydrogen plant

gate costs start leveling out in the order of 2-6 €/kgH2.

13

While the occurrence of surplus may result in negative electricity prices in some countries in the short term, it has been

assumed that longer term renewable ‘surplus’ electricity will need to have a price that reflects the generation costs, as otherwise this will be an impediment for further renewables rollout.

14 Electrolyser CAPEX and average electricity prices for the upper and lower bound vary between 1,200/500 €/kW and 52/39

€/MWh, respectively.



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Figure 6: Range of actual and allowable hydrogen production costs for different end-uses

Based on these assumptions and according to the analysis, to be cost-competitive

the following hydrogen plant gate costs would be required (excluding distribution and

margins):

for sales into the mobility market: between 2-5 €/kgH2 (excluding distribution to

hydrogen refueling station, value added tax, fuel tax, and actual station cost),

for sales to industry: between 2-3 €/kgH2,

for injection into the natural gas grid: between 1-1.5 €/kgH2

for conversion into Synthetic Natural Gas (SNG) by methanation: less than

1 €/kgH2, and

for re-electrification: less than 2 €/kgH2.

This compares to actual plant gate costs in the order of 2-6 €/kgH2. The scenario

analysis indicates that, except for the use in the mobility sector, no other hydrogen

use will result in a positive business case under the assumed energy and CO2 price

conditions and in the absence of favourable policy support measures. The

simulations further show that under the assumptions of this study hydrogen storage

for power-to-power applications, i.e. re-electrification, is economically not attractive;

however, it may become a necessity with a very high renewables share and with very

stringent CO2 emission limits, but would require the right policy incentives.

From the economic analysis of the commercial viability of hydrogen used in the

aforementioned relevant markets, the hydrogen-for-transport market clearly emerged

as the most attractive one, for each country. The reason is that the sales price

benchmark for hydrogen is set by conventional liquid fuels, in combination with the

poorer efficiency of conventional drive systems compared to hydrogen FCEVs. In any

of the other markets, where hydrogen from electrolysis has to compete on a heating

value basis with the price of natural gas, it is not cost-competitive under the energy

and CO2 price assumptions considered.



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Summary and conclusions

In summary, the analysis of all case studies for hydrogen underground storage

arrives at the following high-level conclusions:

In the considered HyUnder countries, a share of intermittent renewables which

covers about 30-40% of the national electricity demand already could result in

some TWh’s of so-called surplus electricity that needs to be accommodated in

the energy system. Higher shares of 60-80%, and more, could result in tens of

TWh’s of surplus electricity, annually, in countries such as Germany, the

Netherlands, Spain and the UK.

Underground storage of hydrogen in salt caverns is a technically feasible

option for large-scale storage of electricity, but requires a suitable geology as

well as public acceptance.

There is geological potential for underground hydrogen storage in salt caverns

in all countries scrutinized. In particular, Germany and the Netherlands seem

to offer good geological conditions in their northern parts. Initially, there will be

a preference for existing natural gas storage sites because of availability of

required infrastructures.

The specific construction costs of salt caverns decrease significantly with size,

with investments for caverns >500,000 m3 in brown field sites ranging from

40-60 €/m3. Depending on the distance to a suitable brine processing or

disposal site, the costs for a new brine pipeline may add significantly to the

total cavern construction costs. Likewise, cushion gas, which accounts for up

to one third of the hydrogen gas volume, represents another significant cost

element.

Electrolysis dominates the total costs of an integrated production and

underground hydrogen storage facility with over 80% (at some 50%

utilization), of which electricity costs have a major share. Although a cavern

requires a significant upfront investment, it has a relatively small contribution

to the total specific hydrogen costs of <0.5 €/kg.

Despite the higher specific costs of a smaller cavern of some 50,000 m3

compared to a large cavern, the impact of the cavern investment is still

relatively small and may initially justify the development of smaller caverns.

Besides electrolyser CAPEX and electricity purchase prices, the costs of

hydrogen from electrolysis strongly depend on the electrolyser utilization. At

less than about 2,000 hours the capital costs start to dominate the production

costs, making hydrogen from electrolysis increasingly expensive. Because

simulations indicate that it may take quite some time before situations with

significantly more than 2,000 hours of surplus are reached, storage of surplus



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electricity as hydrogen does not seem to represent a near-term economically

viable case. Improving the utilization and therefore the economics of

electrolysis would require the purchase of additional electricity from the grid.

Hydrogen energy storage as a means to store renewable electricity via

electrolysis and underground storage is economically very challenging. In the

short term, under the assumptions taken, the transport sector is the only

market expected to allow a hydrogen sales price that may enable the

commercial operation of an integrated hydrogen electrolysis and storage plant.

Where hydrogen from water electrolysis has to compete on a heating value

basis with natural gas, i.e. where the benchmark for the hydrogen sales price

is set by the price of natural gas, such as in the case of admixture to the

natural gas grid, when used as feedstock in industry or for re-electrification, it

is not economic. Therefore, potential business cases for other sectors depend

on the “willingness-to-pay a premium” by the end-user, or a very favourable

policy support. Specifically, the use of ‘low-CO2’ hydrogen (from electrolysis) in

industry depends on its cost-competitiveness against natural gas reforming

(SMR). It is questionable whether this will happen in the absence of a

regulation that allows monetizing its potential CO2 benefits.

Not any single industry sector alone will create a viable business case for

underground hydrogen storage. Initially, hydrogen energy storage would need

a combined pull from the power balancing market and the mobility sector, as it

is otherwise unlikely to be implemented widely. Over time, other markets

would have to fully develop to leverage the economic synergies with hydrogen

energy storage.

Sensitivity analysis indicates that the most important factors for a potential

business case are both low electrolyser CAPEX and significant periods of low

electricity prices, which in the case of re-electrification should be accompanied

by a very high volatility, i.e a very high spread in electricity prices. The future

development of electricity prices, and more generally electricity market

designs, and the actual pricing of ‘surplus’ electricity are among the biggest

uncertainties. Other factors that could contribute to a positive business case

include favourable feed-in tariffs for ‘green’ fuels, reduced grid fees and a

significant increase of CO2 certificate prices to a level of 100 €/t.

The decarbonisation of the European energy system faces the challenge of how to

integrate an increasing share of intermittent renewable energies. Hydrogen is one of

the options that may facilitate this integration, but is in competition with other options.

Concluding, it can be said that underground hydrogen storage may become a viable

option for large-scale electricity storage for weeks and months and make economic



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sense in places with (i) suitable geology, (ii) electricity generation from intermittent

renewables and surplus in the order of tens of TWhs over extended periods, (iii) low

electricity prices during a significant part of the year and (iv) a favourable policy

framework. However, in the “merit order of flexibility solutions” to integrate fluctuating

renewable energies, hydrogen is certainly not the first option that will be applied and

its competiveness as storage option hinges on its successful introduction as low-CO2

energy carrier in other sectors, most importantly the emergence of hydrogen mobility.

Outlook

The increasing need for flexibility options to facilitate ongoing implementation of

electricity from intermittent renewable energy sources is not expected to drive the

deployment of hydrogen energy storage on a structural basis in the near-term. But

hydrogen definitely has a role to play in the longer term as a low/zero-CO2 energy

vector in a highly decarbonised energy system. To use its full potential, hydrogen

needs to become an integral part of the energy system as universal energy carrier

next to electricity, with its additional capability of electricity storage.

An example of this role already becomes apparent in the automotive industry where

hydrogen developments have entered a new phase. The German H2Mobility

initiative, for example, has recently announced plans to establish 400 hydrogen

refuelling stations until 2023, and similar market preparation and early market

development initiatives are being developed in other European countries like the UK

or France, as well as in Japan, the USA and in South Korea. Furthermore, several

OEMs (Toyota, Honda, Hyundai, and Daimler) have signalled intentions for market

introduction of FCEVs between 2015 and 2017. Fuel-cell based electric mobility in

combination with hydrogen from water electrolysis, ideally using renewable

electricity, is also one of the few options able to meet future CO2 emission reduction

targets for the transport sector.

The HyUnder project has solely focused on the role of underground hydrogen

storage as a technically feasible means for large-scale electricity storage, without in

detail considering hydrogen energy storage in the context of the wider set of options

to integrate fluctuating renewables. While technically feasible, the economic viability

of hydrogen as a means for renewable electricity storage will depend on many

energy system-specific parameters. These comprise the emergence of new

structures in the power markets with a high renewable electricity share, a new market

design for ancillary services as well as the level and spread of electricity prices. Their

influence should be analysed in more detail and in the context of other means to

integrate renewables at large-scale, such as the extent of curtailment, the ability of

the required electricity grid extension to keep pace with the build-out of renewable

generation capacity or the impact of large-scale deployment of battery storage:



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Specifically, a need for further assessment has been identified whether it will

be possible to improve the business case for electrolysis in the short to

medium term by leveraging additional revenues from the balancing power

market, thereby easing the pathway through the early implementation phase.

This could be the bundling of ancillary grid services performed by

electrolysers, which would be additional to the provision of large-scale energy

storage, and which today is also partially impeded by existing regulations.

The penetration of renewable energies is increasing all across Europe and

hence the intermittency of electricity supply. If underground hydrogen storage

is expected to play a role in a future renewable energy system, there is a need

for hands-on operational experience and demonstration in preparation of

future markets, as it may well take more than a decade from the decision to

start developing first hydrogen salt cavern projects to the implementation of

the learnings of such projects in appropriate technical standards and suitable

policy, market and regulatory frameworks. This would call for action to

incentivise the development of demonstration projects.

Although residual electricity storage per se does not justify the construction of

a hydrogen cavern in the short term, cavern storage may enable other

hydrogen applications and business cases in relation to its use in industry and

transport, such as for (back-up) supply and trading, as distribution hub as well

as for hydrogen import/export; given the stochastic nature of the hydrogen

production profile from surplus electricity, large-scale hydrogen admixture to

the natural gas grid would also require buffering capacity in order to maintain a

constant gas composition. Incentivizing the construction of hydrogen caverns

for these applications, which may be more economically viable use cases,

would put the required infrastructure in place that could later on also be used

for large-scale storage of electricity.

Especially during the early transition and introduction period, all options and all

markets are in need of favourable policy and regulatory frameworks with high

level of continuity, in order to reduce early investment risks. Specific policy

measures have not been defined in the project.

The HyUnder project was initially motivated by the fact that many studies hint at a

significant (double digit TWh) amount of surplus renewable electricity supposed to

occur by 2050, at which scale the conversion to hydrogen (as a first step) is currently

the only storage option considered feasible, given its energy storage potential.

However, the underlying economic assessment of all case studies has shown that

the development of potential business cases will be challenging; this is mainly due to

the fact that hydrogen from electrolysis struggles to be cost-competitive with other



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hydrogen production routes, all the more in the absence of regulation that enables

the monetization of its potential CO2 benefits. Without (the pull of) an emerging

hydrogen mobility market and the exploitation of synergies between different energy

sectors (electricity generation and transport) as well as a favourable and sustained

policy support, hydrogen underground storage will be difficult to develop.

This apparent mismatch between the perceived technical necessity for large-scale

electricity storage on the one hand and low profitability of hydrogen underground

storage for most application cases on the other hand, leads to the question how else

to enable and incentivise the integration of an increasing share of intermittent

renewables as a means to achieve the EU’s long-term climate targets.

Recommendations to the FCH JU

Maintain focus on electrolysis as a key technology for low-CO2 hydrogen

production. Reach technology cost goals by R&D, and implement calls that

aim at demonstrating and improving the performance of electrolysers for

electricity storage and ancillary service applications across a number of

countries with a high expected share of intermittent renewables.

Perform a review of regulatory regimes for ancillary services like balancing

power in all EU countries and the potential role for electrolysers, as a means

to leverage additional revenue streams.

Maintain a placeholder for an integrated electrolysis and underground

hydrogen storage demonstration project in the Multi Annual Work Programme

(MAWP) in order to gain operational experience, engage with public

authorities on permitting requirements and test public acceptance. A small-

scale project may entail a 50,000 m3 cavern and 10 MWel installed electrolyser

capacity; the total costs for such a project, including investment for topside

facilities (hydrogen compressors and purification), operational costs and

project development are estimated to be in the order of 30-40 M€.

Review the case for underground hydrogen storage in the EU in 2018 to

decide on the placement of a call for proposals towards the end of the FCH JU

program; this should include a review of the business cases for various

hydrogen applications and the external energy-political and regulatory

environment, as well as the identification of locations that offer promising

opportunities to develop first commercial projects. Depending on the business

case outlook this could result in the development of a European Action or

Implementation Plan.

Further practical understanding of the technical challenges of storing large

quantities of hydrogen in caverns is required. This includes the interplay of the



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rock formations with the well with its technical installations (steel, cements,

seals) and potential reactions with hydrogen. In addition, given the limited

geographical spread of suitable salt formations for hydrogen storage,

feasibility studies could focus on exploring porous formations (aquifers and

depleted gas reservoirs) for underground storage.

Explore business cases for hydrogen caverns other than for electricity storage,

such as for hydrogen back-up supply for industry, as distribution hubs for

mobility markets and to facilitate future import/export of hydrogen, possibly

including building a strategic energy reserve.

“assessment of the potential, the actors and relevant

Documents